Berry Petroleum Corporation (NASDAQ: BRY) (“Berry” or the
“Company”) today reported a net loss of $34 million or $0.42 per
diluted share and adjusted net income of $24 million or $0.30 per
diluted share for the first quarter of 2019. In addition, the Board
approved a regular $0.12 per share dividend for the second quarter
of 2019.
Highlights for the Quarter
- Adjusted EBITDA of $69 million and Unhedged Adjusted EBITDA of
$54 million
- 2.2 million shares repurchased; 2.6 million cumulative for $28
million or $10.69/share
- California oil price realizations of 93% of Brent pricing or
$59.16/Bbl before hedging
- Capital Expenditures of $49 million with approximately 87%
directed to California oil development
- Drilled 96 wells in the quarter, on track for approximately 400
wells to be drilled in 2019
- Full-year production and spending are on track
Trem Smith, Berry board chair, chief executive officer and
president stated, “Berry continues to execute its 2019 development
plan in line with our expectations, as our full-year production and
spending are on track. California is a unique energy market
compared to the rest of the United States as it is a Brent-based
and natural gas short market. Being Brent-based is a big
advantage for Berry but, as a natural gas consumer, the lack of
natural gas storage can cause wide fluctuations in pricing.
We saw that impact in our first quarter as the western United
States was cool and wet increasing the demand for natural gas and,
as a result, increasing pricing and negatively impacting our
results for the quarter. However, these prices are
incorporated in our annual guidance which is not changing. In
addition, to better manage the largest portion of our operating
expenses (OpEx), energy costs, and provide better visibility into
our simple financial model we have now hedged the majority of our
gas needs for the next 18 months."
First Quarter Results
For the first quarter, Berry reported Adjusted EBITDA of $69
million, down $13 million from $82 million in the fourth quarter of
2018. Relative to the fourth quarter, the first quarter had lower
oil prices, which were partially protected by our oil hedge, flat
production and substantially higher fuel gas costs which impacted
our OpEx. Adjusted EBITDA, on an unhedged basis, was $54 million in
the first quarter compared to $73 million in the fourth quarter,
impacted primarily by lower oil prices.
California oil prices before hedges for the first quarter
averaged $59.16/Bbl which were 6% lower than the $62.65/Bbl
realized in the fourth quarter. Realized oil prices for the Company
before hedges of $56.88/Bbl were 8% lower than the fourth quarter
average of $61.48.
For the first quarter, Operating Expenses ("OpEx") totaled $54
million or $21.71/Boe compared to $48 million or $18.77/Boe in the
fourth quarter. The price of natural gas we purchased for our steam
operations was unseasonably high in the first quarter, nearly $5
million higher than the prior quarter. On a comparative
basis, our first quarter OpEx was also negatively impacted from
selling our East Texas natural gas assets in November, which had a
lower cost on a per BOE basis compared to our other operations.
OpEx consists of lease operating expenses ("LOE"), as well as
expenses and third-party revenues from electricity generation,
transportation and marketing activities and the effect of
derivative settlements (received or paid) for gas purchases while
excluding taxes other than income taxes.
General and administrative expenses were $14.3 million for the
first quarter compared to $16.1 million for the fourth quarter of
2018. The improvement was due in large part to the fact that the
fourth quarter was impacted by higher stock compensation associated
with performance shares meeting target thresholds. Non-recurring
restructuring and other costs continued to decline in the first
quarter. Adjusted general and administrative expenses were $11.6
million or $4.63/Boe for the first quarter compared to $11.5
million or $4.49/Boe for the fourth quarter.
Taxes, other than income taxes were $8.1 million, or $3.23/Boe
for the first quarter, compared to $7.8 million or $3.04/Boe in the
fourth quarter.
Capital expenditures totaled $49 million for the first quarter
compared to $53 million for the fourth quarter, in both periods
largely focused on drilling in California.
Adjusted net income was $24 million for the first quarter
compared to $35 million for the fourth quarter of 2018. The
decrease was due to the same factors affecting Adjusted EBITDA,
namely lower oil prices and higher fuel gas costs, as well as
corporate tax rates which increased slightly from 23% in the fourth
quarter of 2018 to 28% in the first quarter of 2019.
In April 2019, we completed our semi-annual RBL borrowing base
redetermination, which was affirmed at $750 million. We
elected to keep our lenders’ commitment at $400
million. At April 30 we had no borrowings, and
availability of $391 million due to $9 million of outstanding
letters of credit. Our liquidity was $395 million including a
cash balance of $4 million.
Dividend Announcement
On May 8, 2018 the Board declared a regular dividend for the
second quarter at a rate of $0.12 per share on the Company’s
outstanding common stock. This is the Company's fourth regular
quarterly dividend, and the Company, subject to approval by the
Board, intends to pay a similar dividend in future quarters.
The second quarter dividend is payable on July 15, 2019 to
shareholders of record at the close of business on June 14,
2019.
Earnings Conference Call
The Company will host a conference call May 9, 2019 to discuss
these results:
| Live Call Date: |
Thursday, May 9, 2019 |
| Live Call Time: |
11:00 a.m. Eastern Time (8
a.m. Pacific Time) |
| Live Call Dial-in: |
877-491-5169 from the
U.S. |
| |
720-405-2254 from
international locations |
| Live Call Passcode: |
5569905 |
| |
|
A live audio webcast will be available on the “Investors”
section of Berry’s website
at berrypetroleum.com/investors. An audio replay will be
available shortly after the broadcast:
| Replay Dates: |
Through Thursday, May 23,
2019 |
| Replay Dial-in: |
855-859-2056 from the
U.S. |
| |
404-537-3406 from
international locations |
| Replay Passcode: |
5569905 |
| |
|
A replay of the audio webcast will also be archived on the
“Investors” section of Berry’s website
at berrypetroleum.com/investors. In addition, an investor
presentation will be available on the Company’s website.
About Berry Petroleum
Berry Petroleum Corporation is a publicly-traded (NASDAQ:BRY)
western United States independent upstream energy company with a
focus on the conventional, long-lived oil reserves in the San
Joaquin basin of California. More information can be found at the
Company’s website at www.berrypetroleum.com.
Forward Looking Statements
The information in this press release includes
forward-looking statements that involve risks and uncertainties
that could materially affect our expected results of operations,
liquidity, cash flows and business prospects. Such statements
specifically include our expectations as to our future:
- financial position,
- liquidity,
- cash flows,
- results of operations and business strategy,
- potential acquisition opportunities,
- other plans and objectives for operations,
- maintenance capital requirements,
- expected production and costs,
- reserves,
- hedging activities,
- return of capital,
- capital investments and other guidance.
Actual results may differ from expectations,
sometimes materially, and reported results should not be considered
an indication of future performance. Factors (but not all the
factors) that could cause results to differ include:
- volatility of oil, natural gas and natural gas liquids (NGL)
prices;
- our ability to obtain permits and otherwise to meet our
proposed drilling schedule and to successfully drill wells that
produce oil and natural gas in commercially viable quantities;
- price and availability of natural gas;
- changes in laws or regulations;
- our ability to use derivative instruments to manage commodity
price risk;
- the impact of environmental, health and safety, and other
governmental regulations, and of current or pending or future
legislation;
- uncertainties associated with estimating proved reserves and
related future cash flows;
- our ability to replace our reserves through exploration and
development activities;
- timely and available drilling and completion equipment and crew
availability and access to necessary resources for drilling,
completing and operating well;
- our ability to make acquisitions and successfully integrate any
acquired businesses; and
- other material risks that appear in the Risk Factors section of
the prospectus filed with the SEC in connection with our initial
public offering.
You can typically identify forward-looking
statements by words such as aim, anticipate, achievable, believe,
continue, could, estimate, expect, forecast, goal, guidance,
intend, likely, may, might, objective, outlook, plan, potential,
predict, project, seek, should, target, will or would and other
similar words that reflect the prospective nature of events or
outcomes. We undertake no responsibility to publicly release the
result of any revision of our forward-looking statements after the
date they are made.
Contact
Contact: Berry Petroleum CorporationTodd Crabtree - Manager,
Investor Relations(661) 616-3811ir@bry.com
TABLES FOLLOWING
The financial information and certain other
information presented have been rounded to the nearest whole number
or the nearest decimal. Therefore, the sum of the numbers in a
column may not conform exactly to the total figure given for that
column in certain tables. In addition, certain percentages
presented here reflect calculations based upon the underlying
information prior to rounding and, accordingly, may not conform
exactly to the percentages that would be derived if the relevant
calculations were based upon the rounded numbers, or may not sum
due to rounding.
SUMMARY OF RESULTS
| |
Three Months Ended |
| |
March 31, 2019 |
|
December 31, 2018 |
|
March 31, 2018 |
| |
|
| |
($ and shares in thousands, except per share amounts) |
| Statement of
Operations Data: |
|
|
|
|
|
| Revenues and
other: |
|
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
131,102 |
|
|
$ |
142,861 |
|
|
$ |
125,624 |
|
|
Electricity sales |
9,729 |
|
|
9,517 |
|
|
5,453 |
|
|
Gains (losses) on oil derivatives |
(65,239 |
) |
|
127,160 |
|
|
(34,644 |
) |
|
Marketing revenues |
830 |
|
|
534 |
|
|
785 |
|
|
Other revenues |
117 |
|
|
274 |
|
|
66 |
|
|
Total revenues and other |
76,539 |
|
|
280,346 |
|
|
97,284 |
|
| |
|
|
|
|
|
| Expenses and
other: |
|
|
|
|
|
|
Lease operating expenses |
57,928 |
|
|
51,308 |
|
|
44,303 |
|
|
Electricity generation expenses |
7,760 |
|
|
6,764 |
|
|
4,590 |
|
|
Transportation expenses |
2,173 |
|
|
2,220 |
|
|
2,978 |
|
|
Marketing expenses |
851 |
|
|
716 |
|
|
580 |
|
|
General and administrative expenses |
14,340 |
|
|
16,130 |
|
|
11,985 |
|
|
Depreciation, depletion and amortization |
24,585 |
|
|
24,253 |
|
|
18,429 |
|
|
Taxes, other than income taxes |
8,086 |
|
|
7,829 |
|
|
8,256 |
|
|
(Gains) losses on natural gas derivatives |
(2,115 |
) |
|
(4,477 |
) |
|
— |
|
|
(Gains) losses on sale of assets and other, net |
1,245 |
|
|
(3,269 |
) |
|
— |
|
|
Total expenses and other |
114,853 |
|
|
101,474 |
|
|
91,121 |
|
| |
|
|
|
|
|
| Other income
(expenses): |
|
|
|
|
|
|
Interest expense |
(8,805 |
) |
|
(8,820 |
) |
|
(7,796 |
) |
|
Other, net |
154 |
|
|
108 |
|
|
27 |
|
|
Total other income (expenses) |
(8,651 |
) |
|
(8,712 |
) |
|
(7,769 |
) |
| Reorganization items, net |
(231 |
) |
|
1,498 |
|
|
8,955 |
|
| Income (loss) before
income taxes |
(47,196 |
) |
|
171,658 |
|
|
7,349 |
|
| Income tax expense
(benefit) |
(13,098 |
) |
|
39,890 |
|
|
939 |
|
| Net income
(loss) |
(34,098 |
) |
|
131,768 |
|
|
6,410 |
|
| Series A preferred stock
dividends |
— |
|
|
— |
|
|
(5,650 |
) |
| Net income (loss)
attributable to common stockholders |
$ |
(34,098 |
) |
|
$ |
131,768 |
|
|
$ |
760 |
|
| |
|
|
|
|
|
| Net income (loss) per
share attributable to common stockholders |
|
|
|
|
|
| Basic |
$ |
(0.42 |
) |
|
$ |
1.56 |
|
|
$ |
0.02 |
|
| Diluted |
$ |
(0.42 |
) |
|
$ |
1.56 |
|
|
$ |
0.02 |
|
| |
|
|
|
|
|
| Weighted-average common shares
outstanding - basic |
81,765 |
|
|
84,367 |
|
|
38,602 |
|
| Weighted-average common shares
outstanding - diluted |
81,765 |
|
|
84,592 |
|
|
38,827 |
|
| |
|
|
|
|
|
| Adjusted net income
(loss) |
$ |
24,264 |
|
|
$ |
34,809 |
|
|
$ |
15,034 |
|
| Adjusted EBITDA |
$ |
68,502 |
|
|
$ |
81,669 |
|
|
$ |
44,503 |
|
| Adjusted EBITDA unhedged |
$ |
53,598 |
|
|
$ |
72,990 |
|
|
$ |
62,352 |
|
| Levered free cash flow |
$ |
526 |
|
|
$ |
9,531 |
|
|
$ |
15,325 |
|
| Levered free cash flow
unhedged |
$ |
(14,378 |
) |
|
$ |
852 |
|
|
$ |
33,174 |
|
| Adjusted general and
administrative expenses |
$ |
11,587 |
|
|
$ |
11,533 |
|
|
$ |
8,919 |
|
| Effective Tax Rate |
28 |
% |
|
23 |
% |
|
13 |
% |
| |
|
|
|
|
|
|
|
|
| |
Three Months Ended |
| |
March 31, 2019 |
|
December 31, 2018 |
|
March 31, 2018 |
| |
|
|
|
|
|
| |
($ in thousands) |
| Cash Flow
Data: |
|
|
|
|
|
| Net cash provided by (used in)
operating activities |
$ |
19,111 |
|
|
$ |
95,767 |
|
|
$ |
27,592 |
|
| Net cash provided by (used in)
investing activities |
$ |
(50,805 |
) |
|
$ |
(36,694 |
) |
|
$ |
(19,876 |
) |
| Net cash provided by (used in)
financing activities |
$ |
(35,324 |
) |
|
$ |
(14,306 |
) |
|
$ |
12,185 |
|
| |
March 31, 2019 |
|
December 31, 2018 |
| |
|
| |
($ and shares in thousands) |
| Balance Sheet
Data: |
|
|
|
|
Total current assets |
$ |
97,802 |
|
|
$ |
229,022 |
|
| Total property, plant and
equipment, net |
$ |
1,469,127 |
|
|
$ |
1,442,708 |
|
| Total current liabilities |
$ |
114,630 |
|
|
$ |
144,118 |
|
| Long-term debt |
$ |
391,947 |
|
|
$ |
391,786 |
|
| Total equity |
$ |
939,129 |
|
|
$ |
1,006,446 |
|
| Outstanding common stock
shares as of |
81,879 |
|
|
81,202 |
|
SUMMARY BY AREA
The following table shows a summary by area of
our selected historical financial information and operating data
for the periods indicated.
| |
California (San Joaquin and Ventura basins) |
|
Rockies (Uinta and Piceance basins) |
| |
Three Months Ended |
|
Three Months Ended |
| |
March 31, 2019 |
|
March 31, 2018 |
|
March 31, 2019 |
|
March 31, 2018 |
|
($ in thousands, except prices) |
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
111,896 |
|
|
$ |
105,544 |
|
|
$ |
19,206 |
|
|
$ |
18,715 |
|
| Operating income(a) |
$ |
37,357 |
|
|
$ |
47,258 |
|
|
$ |
4,779 |
|
|
$ |
3,445 |
|
| Depreciation, depletion, and
amortization (DD&A) |
$ |
21,342 |
|
|
$ |
14,905 |
|
|
$ |
3,244 |
|
|
$ |
3,031 |
|
| Average daily production
(MBoe/d) |
21.0 |
|
|
18.8 |
|
|
6.8 |
|
|
6.6 |
|
| Production (oil% of
total) |
100 |
% |
|
100 |
% |
|
46 |
% |
|
35 |
% |
| Realized sales prices: |
|
|
|
|
|
|
|
|
Oil (per Bbl) |
$ |
59.16 |
|
|
$ |
62.37 |
|
|
$ |
41.38 |
|
|
$ |
60.29 |
|
|
NGLs (per Bbl) |
$ |
— |
|
|
$ |
— |
|
|
$ |
24.42 |
|
|
$ |
26.46 |
|
|
Gas (per Mcf) |
$ |
— |
|
|
$ |
— |
|
|
$ |
3.77 |
|
|
$ |
2.58 |
|
| Capital expenditures |
$ |
42,509 |
|
|
$ |
15,301 |
|
|
$ |
5,313 |
|
|
$ |
378 |
|
__________
(a) Operating income includes
oil, natural gas and NGL sales, offset by operating expenses,
general and administrative expenses, DD&A, and taxes, other
than income taxes.
COMMODITY PRICING
| |
Three Months Ended |
| |
March 31, 2019 |
|
December 31, 2018 |
|
March 31, 2018 |
| Realized Sales Prices
(weighted-average) |
|
|
|
|
|
|
Oil without hedge ($/Bbl) |
$ |
56.88 |
|
|
$ |
61.48 |
|
|
$ |
62.14 |
|
| Effects of scheduled
derivative settlements ($/Bbl) |
$ |
5.15 |
|
|
$ |
2.88 |
|
|
$ |
(9.40 |
) |
| Oil with hedge ($/Bbl) |
$ |
62.03 |
|
|
$ |
64.36 |
|
|
$ |
52.74 |
|
| Natural gas ($/Mcf) |
$ |
3.83 |
|
|
$ |
3.86 |
|
|
$ |
2.64 |
|
| NGLs ($/Bbl) |
$ |
24.35 |
|
|
$ |
20.39 |
|
|
$ |
25.56 |
|
| |
|
|
|
|
|
| Index
Prices |
|
|
|
|
|
| Brent oil ($/Bbl) |
$ |
63.83 |
|
|
$ |
68.08 |
|
|
$ |
67.16 |
|
| WTI oil ($/Bbl) |
$ |
54.87 |
|
|
$ |
58.81 |
|
|
$ |
62.87 |
|
| Henry Hub natural gas
($/MMBtu) |
$ |
2.92 |
|
|
$ |
3.64 |
|
|
$ |
3.00 |
|
CURRENT HEDGING SUMMARY
As of April 30, 2019, our positions were as follows:
| |
Q2 2019 |
|
Q3 2019 |
|
Q4 2019 |
|
FY 2020 |
| Oil Calls Options
(Brent): |
|
|
|
|
|
|
|
|
Hedged volume (MBbls) |
180 |
|
|
92 |
|
|
92 |
|
|
— |
|
|
Weighted average price ($/Bbl) |
$ |
70.00 |
|
|
$ |
81.00 |
|
|
$ |
81.00 |
|
|
$ |
— |
|
| Oil Put Options
(Brent): |
|
|
|
|
|
|
|
|
Hedged volume (MBbls) |
1,092 |
|
|
460 |
|
|
460 |
|
|
— |
|
|
Weighted-average price ($/Bbl) |
$ |
60.00 |
|
|
$ |
50.00 |
|
|
$ |
50.00 |
|
|
$ |
— |
|
| Fixed Price Oil Swaps
(Brent) |
|
|
|
|
|
|
|
|
Hedged volume (MBbls) |
881 |
|
|
1,380 |
|
|
1,380 |
|
|
2,928 |
|
|
Weighted average price ($/Bbl) |
$ |
73.86 |
|
|
$ |
72.70 |
|
|
$ |
72.21 |
|
|
$ |
67.66 |
|
| Fixed Price Oil Swaps
(WTI): |
|
|
|
|
|
|
|
|
Hedged volume (MBbls) |
61 |
|
|
92 |
|
|
92 |
|
|
121 |
|
|
Weighted average price ($/Bbl) |
$ |
61.75 |
|
|
$ |
61.75 |
|
|
$ |
61.75 |
|
|
$ |
61.75 |
|
| Oil basis differential
positions (Brent-WTI basis swaps): |
|
|
|
|
|
|
|
|
Hedged volume (MBbls) |
46 |
|
|
46 |
|
|
46 |
|
|
— |
|
|
Weighted average price ($/Bbl) |
$ |
(1.29 |
) |
|
$ |
(1.29 |
) |
|
$ |
(1.29 |
) |
|
$ |
— |
|
| Fixed Price Gas
Purchase Swaps (Kern, Delivered): |
|
|
|
|
|
|
|
|
Hedged volume (MMBtu) |
4,255,000 |
|
|
4,600,000 |
|
|
3,685,000 |
|
|
10,675,000 |
|
|
Weighted average price ($/MMBtu) |
$ |
2.81 |
|
|
$ |
2.91 |
|
|
$ |
2.97 |
|
|
$ |
3.01 |
|
| Fixed Price Gas
Purchase Swaps (SoCal Citygate): |
|
|
|
|
|
|
|
|
Hedged volume (MMBtu) |
305,000 |
|
|
460,000 |
|
|
460,000 |
|
|
2,290,000 |
|
|
Weighted average price ($/MMBtu) |
$ |
3.80 |
|
|
$ |
3.80 |
|
|
$ |
3.80 |
|
|
$ |
3.80 |
|
OPERATING EXPENSES
| |
Three Months Ended |
| |
March 31, 2019 |
|
December 31, 2018 |
|
March 31, 2018 |
| |
|
| |
($ in thousands except per Boe amounts) |
|
Lease operating expenses |
$ |
57,928 |
|
|
$ |
51,308 |
|
|
$ |
44,303 |
|
| Electricity generation
expenses |
7,760 |
|
|
6,764 |
|
|
4,590 |
|
| Electricity sales(a) |
(9,729 |
) |
|
(9,517 |
) |
|
(5,453 |
) |
| Transportation expenses |
2,173 |
|
|
2,220 |
|
|
2,978 |
|
| Transportation sales(a) |
(117 |
) |
|
(274 |
) |
|
(66 |
) |
| Marketing expenses |
851 |
|
|
716 |
|
|
580 |
|
| Marketing revenues(a) |
(830 |
) |
|
(534 |
) |
|
(785 |
) |
| Derivative settlements
(received) paid for gas purchases(a) |
(3,724 |
) |
|
(2,407 |
) |
|
— |
|
|
Total operating expenses(a) |
$ |
54,312 |
|
|
$ |
48,276 |
|
|
$ |
46,147 |
|
| |
|
|
|
|
|
| Lease operating expenses
($/Boe) |
$ |
23.16 |
|
|
$ |
19.96 |
|
|
$ |
18.80 |
|
| Electricity generation
expenses ($/Boe) |
3.10 |
|
|
2.63 |
|
|
$ |
1.94 |
|
| Electricity sales ($/Boe) |
(3.89 |
) |
|
(3.70 |
) |
|
$ |
(2.31 |
) |
| Transportation expenses
($/Boe) |
0.87 |
|
|
0.86 |
|
|
$ |
1.26 |
|
| Transportation sales
($/Boe) |
(0.05 |
) |
|
(0.11 |
) |
|
— |
|
| Marketing expenses
($/Boe) |
0.34 |
|
|
0.28 |
|
|
$ |
0.25 |
|
| Marketing revenues
($/Boe) |
(0.33 |
) |
|
(0.21 |
) |
|
$ |
(0.33 |
) |
| Derivative settlements
(received) paid for gas purchases ($/Boe) |
(1.49 |
) |
|
(0.94 |
) |
|
— |
|
|
Total operating expenses ($/Boe) |
$ |
21.71 |
|
|
$ |
18.77 |
|
|
$ |
19.61 |
|
| |
|
|
|
|
|
| Total MBoe |
2,501 |
|
2,571 |
|
2,356 |
__________
(a) We report electricity, transportation and
marketing sales separately in our financial statements as revenues
in accordance with GAAP. However, these revenues are viewed and
used internally in calculating operating expenses which is used to
track and analyze the economics of development projects and the
efficiency of our hydrocarbon recovery. We purchase third-party gas
to generate electricity through our cogeneration facilities to be
used in our field operations activities and view the added benefit
of any excess electricity sold externally as a cost
reduction/benefit to generating steam for our thermal recovery
operations. Marketing expenses mainly relate to natural gas
purchased from third parties that moves through our gathering and
processing systems and then is sold to third parties.
Transportation sales, reported in "Other Revenues", relates to
water and other liquids that we transport on our systems on behalf
of third parties.
PRODUCTION STATISTICS
| |
Three Months Ended |
| |
March 31, 2019 |
|
December 31, 2018 |
|
March 31, 2018 |
| Net Oil, Natural Gas
and NGLs Production Per
Day(a): |
|
|
|
|
|
| Oil
(MBbl/d) |
|
|
|
|
|
|
California |
21.0 |
|
|
21.7 |
|
|
18.8 |
|
|
Rockies |
3.1 |
|
|
2.0 |
|
|
2.3 |
|
|
East Texas(c) |
— |
|
|
— |
|
|
— |
|
|
Total oil |
24.1 |
|
|
23.7 |
|
|
21.1 |
|
| Natural gas
(MMcf/d) |
|
|
|
|
|
|
|
|
|
California |
— |
|
|
— |
|
|
— |
|
|
Rockies |
19.5 |
|
|
19.3 |
|
|
22.7 |
|
|
East Texas(c) |
— |
|
|
2.8 |
|
|
4.9 |
|
|
Total natural gas |
19.5 |
|
|
22.1 |
|
|
27.6 |
|
| NGLs
(MBbl/d) |
|
|
|
|
|
|
|
|
|
California |
— |
|
|
— |
|
|
— |
|
|
Rockies |
0.4 |
|
|
0.6 |
|
|
0.5 |
|
|
East Texas(c) |
— |
|
|
— |
|
|
— |
|
|
Total NGLs |
0.4 |
|
|
0.6 |
|
|
0.5 |
|
| Total Production
(MBoe/d)(b) |
27.8 |
|
|
28.0 |
|
|
26.2 |
|
__________
(a) Production represents volumes sold during the
period.
(b) Natural gas volumes have been
converted to Boe based on energy content of six Mcf of gas to one
Bbl of oil. Barrels of oil equivalence does not necessarily result
in price equivalence. The price of natural gas on a barrel of oil
equivalent basis is currently substantially lower than the
corresponding price for oil and has been similarly lower for a
number of years. For example, in the quarter ended March 31,
2019, the average prices of Brent oil and Henry Hub natural gas
were $63.83 per Bbl and $2.92 per MMBtu, respectively, resulting in
an oil-to-gas ratio of approximately 4 to 1 on an energy equivalent
basis.
(c) On November 30, 2018, we sold our
non-core gas-producing properties and related assets located in the
East Texas basin.
CAPITAL EXPENDITURES (ACCRUAL BASIS)
| |
Three Months Ended |
| |
March 31, 2019 |
|
December 31, 2018 |
|
March 31, 2018 |
| |
|
| |
(in thousands) |
|
Capital expenditures (accrual basis) |
$ |
49,099 |
|
|
$ |
53,326 |
|
|
$ |
15,732 |
|
NON-GAAP FINANCIAL MEASURES AND
RECONCILIATIONS
Adjusted EBITDA and Adjusted Net Income (Loss)
are not measures of net income (loss) and Levered Free Cash Flow is
not a measure of cash flow, in all cases, as determined by GAAP.
Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash
Flow are supplemental non-GAAP financial measures used by
management and external users of our financial statements, such as
industry analysts, investors, lenders and rating agencies.
We define Adjusted EBITDA as earnings before
interest expense; income taxes; depreciation, depletion, and
amortization; derivative gains or losses net of cash received or
paid for scheduled derivative settlements; impairments; stock
compensation expense; and other unusual, out-of-period and
infrequent items, including restructuring costs and reorganization
items. We define Levered Free Cash Flow as Adjusted EBITDA less
capital expenditures, interest expense and dividends.
Our management believes Adjusted EBITDA provides
useful information in assessing our financial condition, results of
operations and cash flows and is widely used by the industry and
the investment community. The measure also allows our management to
more effectively evaluate our operating performance and compare the
results between periods without regard to our financing methods or
capital structure. Levered Free Cash Flow is used by management as
a primary metric to plan capital allocation for maintenance and
internal growth opportunities, as well as hedging needs. It also
serves as a measure for assessing our financial performance and our
ability to generate excess cash from operations to service debt and
pay dividends.
Adjusted Net Income (Loss) excludes the impact
of unusual, out-of-period and infrequent items affecting earnings
that vary widely and unpredictably, including non-cash items such
as derivative gains and losses. This measure is used by management
when comparing results period over period. We define Adjusted Net
Income (Loss) as net income (loss) adjusted for derivative gains or
losses net of cash received or paid for scheduled derivative
settlements, other unusual, out-of-period and infrequent items,
including restructuring costs and reorganization items and the
income tax expense or benefit of these adjustments using our
effective tax rate.
While Adjusted EBITDA, Adjusted Net Income
(Loss) and Levered Free Cash Flow are non-GAAP measures, the
amounts included in the calculation of Adjusted EBITDA, Adjusted
Net Income (Loss) and Levered Free Cash Flow were computed in
accordance with GAAP. These measures are provided in addition to,
and not as an alternative for, income and liquidity measures
calculated in accordance with GAAP. Certain items excluded from
Adjusted EBITDA are significant components in understanding and
assessing our financial performance, such as our cost of capital
and tax structure, as well as the historic cost of depreciable and
depletable assets. Our computations of Adjusted EBITDA, Adjusted
Net Income (Loss) and Levered Free Cash Flow may not be comparable
to other similarly titled measures used by other companies.
Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash
Flow should be read in conjunction with the information contained
in our financial statements prepared in accordance with GAAP.
Adjusted General and Administrative Expenses is
a supplemental non-GAAP financial measure that is used by
management. We define Adjusted General and Administrative Expenses
as general and administrative expenses adjusted for non-recurring
restructuring and other costs and non-cash stock compensation
expense. Management believes Adjusted General and Administrative
Expenses is useful because it allows us to more effectively compare
our performance from period to period.
We exclude the items listed above from general
and administrative expenses in arriving at Adjusted General and
Administrative Expenses because these amounts can vary widely and
unpredictably in nature, timing, amount and frequency and stock
compensation expense is non-cash in nature. Adjusted General and
Administrative Expenses should not be considered as an alternative
to, or more meaningful than, general and administrative expenses as
determined in accordance with GAAP. Our computations of Adjusted
General and Administrative Expenses may not be comparable to other
similarly titled measures of other companies.
ADJUSTED NET INCOME (LOSS)
The following table presents a reconciliation of
the GAAP financial measure of net income (loss) to the non-GAAP
financial measure of Adjusted Net Income (Loss).
| |
Three Months Ended |
| |
March 31, 2019 |
|
December 31, 2018 |
|
March 31, 2018 |
| |
|
| |
($ thousands, except per share amounts) |
|
Net income (loss) |
$ |
(34,098 |
) |
|
$ |
131,768 |
|
|
$ |
6,410 |
|
| |
|
|
|
|
|
| Add (Subtract): |
|
|
|
|
|
|
(Gains) losses on oil and natural gas derivatives |
63,124 |
|
|
(131,637 |
) |
|
34,644 |
|
|
Net cash received (paid) for scheduled derivative settlements |
14,904 |
|
|
8,679 |
|
|
(17,849 |
) |
|
(Gains) losses on sale of assets and other, net |
1,245 |
|
|
(3,269 |
) |
|
— |
|
|
Non-recurring restructuring and other costs |
1,329 |
|
|
1,414 |
|
|
2,047 |
|
|
Reorganization items, net |
231 |
|
|
(1,498 |
) |
|
(8,955 |
) |
|
Total additions, net |
80,833 |
|
|
(126,311 |
) |
|
9,887 |
|
| |
|
|
|
|
|
| Income tax (expense) benefit
of adjustments at effective tax rate |
(22,471 |
) |
|
29,352 |
|
|
(1,263 |
) |
| Adjusted net income
(loss) |
$ |
24,264 |
|
|
$ |
34,809 |
|
|
$ |
15,034 |
|
| |
|
|
|
|
|
| Basic EPS on adjusted
income |
$ |
0.30 |
|
|
$ |
0.41 |
|
|
$ |
0.39 |
|
| Diluted EPS on adjusted net
income |
$ |
0.30 |
|
|
$ |
0.41 |
|
|
$ |
0.20 |
|
| |
|
|
|
|
|
| Weighted average shares
outstanding - basic |
81,765 |
|
|
84,367 |
|
|
38,602 |
|
| Weighted average shares
outstanding - diluted |
81,973 |
|
|
84,592 |
|
|
74,672 |
|
ADJUSTED EBITDA AND ADJUSTED EBITDA
UNHEDGED
The following tables present a reconciliation of
the GAAP financial measures of net income (loss) and net cash
(used) by operating activities to the non-GAAP financial measures
of Adjusted EBITDA and Adjusted EBITDA Unhedged.
| |
Three Months Ended |
| |
March 31, 2019 |
|
December 31, 2018 |
|
March 31, 2018 |
| |
|
| |
($ thousands) |
|
Net income (loss) |
$ |
(34,098 |
) |
|
$ |
131,768 |
|
|
$ |
6,410 |
|
| Add (Subtract): |
|
|
|
|
|
|
Interest expense |
8,805 |
|
|
8,820 |
|
|
7,796 |
|
|
Income tax expense (benefit) |
(13,098 |
) |
|
39,890 |
|
|
939 |
|
|
Depreciation, depletion and amortization |
24,585 |
|
|
24,253 |
|
|
18,429 |
|
|
Derivative (gain) loss |
63,124 |
|
|
(131,637 |
) |
|
34,644 |
|
|
Net cash received (paid) for scheduled derivative settlements |
14,904 |
|
|
8,679 |
|
|
(17,849 |
) |
|
(Gain) loss on sale of assets and other |
1,245 |
|
|
(3,269 |
) |
|
— |
|
|
Stock compensation expense |
1,475 |
|
|
3,249 |
|
|
1,042 |
|
|
Non-recurring restructuring and other costs |
1,329 |
|
|
1,414 |
|
|
2,047 |
|
|
Reorganization items, net |
231 |
|
|
(1,498 |
) |
|
(8,955 |
) |
| Adjusted EBITDA |
$ |
68,502 |
|
|
$ |
81,669 |
|
|
$ |
44,503 |
|
| Net cash (received) paid for
scheduled derivative settlements |
(14,904 |
) |
|
(8,679 |
) |
|
17,849 |
|
| Adjusted EBITDA unhedged |
$ |
53,598 |
|
|
$ |
72,990 |
|
|
$ |
62,352 |
|
| |
|
|
|
|
|
| Net cash provided (used) by
operating activities(1) |
19,111 |
|
|
95,767 |
|
|
27,592 |
|
| Add (Subtract): |
|
|
|
|
|
|
Cash interest payments |
14,000 |
|
|
562 |
|
|
2,654 |
|
|
Cash income tax payments |
— |
|
|
(1,901 |
) |
|
— |
|
|
Cash reorganization item (receipts) payments |
— |
|
|
(174 |
) |
|
468 |
|
|
Non-recurring restructuring and other costs |
1,329 |
|
|
1,414 |
|
|
2,047 |
|
|
Other changes in operating assets and liabilities |
34,063 |
|
|
(13,998 |
) |
|
11,742 |
|
| Adjusted EBITDA |
$ |
68,502 |
|
|
$ |
81,669 |
|
|
$ |
44,503 |
|
| Net cash (received) paid for
scheduled derivative settlements |
(14,904 |
) |
|
(8,679 |
) |
|
17,849 |
|
| Adjusted EBITDA unhedged |
$ |
53,598 |
|
|
$ |
72,990 |
|
|
$ |
62,352 |
|
__________
(1) The three months ended March 31,
2019 included $37 million of annual or semi-annual payments that
occur in the first quarter each year such as semi-annual interest
and certain annual royalty payments and other accrued
liabilities.
LEVERED FREE CASH FLOW
The following table presents a reconciliation of
Adjusted EBITDA to the non–GAAP measures of Levered free cash flow.
The reconciliation of Adjusted EBITDA is presented above.
| |
Three Months Ended |
| |
March 31, 2019 |
|
December 31, 2018 |
|
March 31, 2018 |
| |
|
| |
($ thousands) |
|
Adjusted EBITDA |
$ |
68,502 |
|
|
$ |
81,669 |
|
|
$ |
44,503 |
|
| Subtract: |
|
|
|
|
|
|
Capital expenditures - accrual basis |
(49,099 |
) |
|
(53,326 |
) |
|
(15,732 |
) |
|
Interest expense |
(8,805 |
) |
|
(8,820 |
) |
|
(7,796 |
) |
|
Cash dividends declared |
(10,072 |
) |
|
(9,992 |
) |
|
(5,650 |
) |
| Levered free cash flow |
$ |
526 |
|
|
$ |
9,531 |
|
|
$ |
15,325 |
|
| Net cash (received) paid for
scheduled derivative settlements |
(14,904 |
) |
|
(8,679 |
) |
|
17,849 |
|
| Levered free cash flow
unhedged |
$ |
(14,378 |
) |
|
$ |
852 |
|
|
$ |
33,174 |
|
ADJUSTED GENERAL AND ADMINISTRATIVE
EXPENSES
The following table presents a reconciliation of the GAAP
financial measure of general and administrative expenses to the
non-GAAP financial measures of Adjusted general and administrative
expenses.
| |
Three Months Ended |
| |
March 31, 2019 |
|
December 31, 2018 |
|
March 31, 2018 |
| |
|
| |
($ in thousands except per MBoe amounts) |
|
General and administrative expenses |
$ |
14,340 |
|
|
$ |
16,130 |
|
|
$ |
11,985 |
|
| Subtract: |
|
|
|
|
|
|
Non-recurring restructuring and other costs |
(1,329 |
) |
|
(1,414 |
) |
|
(2,047 |
) |
|
Non-cash stock compensation expense |
(1,424 |
) |
|
(3,183 |
) |
|
(1,019 |
) |
| Adjusted general and
administrative expenses |
$ |
11,587 |
|
|
$ |
11,533 |
|
|
$ |
8,919 |
|
| |
|
|
|
|
|
| General and administrative
expenses ($/MBoe) |
$ |
5.73 |
|
|
$ |
6.27 |
|
|
$ |
5.09 |
|
| Subtract: |
|
|
|
|
|
|
Non-recurring restructuring and other costs ($/MBoe) |
(0.53 |
) |
|
(0.55 |
) |
|
(0.87 |
) |
|
Non-cash stock compensation expense ($/MBoe) |
(0.57 |
) |
|
(1.24 |
) |
|
(0.43 |
) |
| Adjusted general and
administrative expenses ($/MBoe) |
$ |
4.63 |
|
|
$ |
4.49 |
|
|
$ |
3.79 |
|
| |
|
|
|
|
|
| Total MBoe |
2,501 |
|
|
2,571 |
|
|
2,356 |
|
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